This invention relates to a method and system for separating components of a multi-component fluid mixture in a well. More specifically the invention relates to a method and system for separating components of a multi-component gas in a wellbore using a gas separation membrane.
Natural gas is an important fuel gas and it is used extensively as a basic raw material in the petrochemical and other chemical process industries. The composition of natural gas varies widely from field to field. Many natural gas reservoirs contain relatively low percentages of hydrocarbons (less than 40%, for example) and high percentages of acid gases, principally carbon dioxide, but also hydrogen sulfide, carbonyl sulfide, carbon disulfide and various mercaptans. Removal of acid gases from natural gas produced in remote locations is desirable to provide conditioned or sweet, dry natural gas either for delivery to a pipeline, natural gas liquids recovery, helium recovery, conversion to liquefied natural gas (LNG), or for subsequent nitrogen rejection. H2S is removed because it is toxic in minute amounts and it is corrosive in the presence of water through the formation of hydrosulfurous acid. Upon combustion, H2S forms sulfur dioxide, a toxic and corrosive compound. CO2 is also corrosive in the presence of water, and it can form dry ice, hydrates and can cause freeze-up problems in pipelines and in cryogenic equipment often used in processing the natural gas. Also, by not contributing to the heating value, CO2 merely adds to the cost of gas transmission.
An important aspect of any natural gas treating process is economics. Natural gas is typically treated in high volumes, making even slight differences in capital and operating costs of the treating unit very significant factors in the selection of process technology. Some natural gas resources are now uneconomical to produce because of processing costs. There is a continuing need for improved natural gas treating processes that have high reliability and represent simplicity of operation.
A number of processes for the recovery or removal of CO2 from natural gas have been proposed and practiced on a commercial scale. The processes vary widely, but generally involve some form of solvent absorption, adsorption on a porous adsorbent, or diffusion through a semipermeable membrane. The use of membranes for gas separation is becoming increasingly more common because of its simplicity.
In a membrane separation system, a mixture of gases, the feed gas, under pressure, is passed across the surface of a membrane that acts as a selective barrier, permitting some components of the gas mixture to pass through more readily than other components. The pressure on the feed side of the system is maintained at a level sufficiently higher than the pressure on the permeate side of the membrane to provide a driving force for the diffusion of the more permeable components of the gaseous mixture through the membrane. The partial pressure of the more permeable gaseous components is also maintained at a higher level on the feed side of the membrane than on the permeate side by constantly removing both the permeate stream and the residue of the feed stream, the retentate stream, from contact with the membrane. While the permeate stream can represent the desired product, in most natural gas permeation processes the desired product is the residue stream, and the permeate stream consists of contaminants which are removed from the feed stream.
Membranes have been proposed for use in wellbores to separate fluids, including for example U.S. Pat. No. 6,015,011 (Hunter); U.S. Pat. No. 5,860,476 (Kjos); U.S. Pat. No. 5,730,871 (Kennedy et al.); U.S. Pat. No. 5,693,225 (Lee); U.S. Pat. No. 4,241,787 (Price); and U.S. Pat. No. 4,171,017 (Klass). Membrane modules in a wellbore have been proposed primarily to separate hydrocarbons (gas or crude oil) from brine. In Lee and Kennedy et al., the hydrocarbons are passed to the earth""s surface and the unwanted brine is injected into a subterranean discharge formation. Kjos proposed using wellbore membranes in combination with downhole cyclones to separate from a natural gas stream unwanted gases, including H2S, CO2, and H2O. Kjos further proposed passing the unwanted CO2 into a subterranean waste zone. One shortcoming of Kjos is that no procedure is disclosed for carrying out the membrane separation process.
A need exists for an improved gas separation method and system for economically separating one or more unwanted components from a natural gas stream.
The invention is a method and system of separating a multi-component fluid in a wellbore. At least one fluid separation membrane comprising a feed side and a permeate side is incorporated in the wellbore. A flowing stream of the multi-component fluid obtained from a subterranean zone being in fluid communication with the wellbore is passed across the feed side of the membrane at a first pressure. A retentate stream depleted in at least one component compared to the multi-component fluid is withdrawn from the feed side of the membrane and passed to the earth""s surface. A permeate stream at a second pressure is withdrawn from the permeate side, in which the permeate stream is enriched in at least one component compared with the multi-component fluid. The second pressure is controlled to maintain the second pressure below the first pressure.